System For Inhibiting Flow Of Fracturing Fluid In An Offset Wellbore

ABSTRACT

Processes and systems for inhibiting the flow of fracturing fluid through one or more subterranean wells offset from the subterranean well being fractured. A fracturing fluid is injected under pressure via a first well penetrating and in fluid communication with a subterranean region of interest so as to fracture the subterranean region. A second fluid is positioned within one or more second subterranean wells penetrating and in fluid communication with the subterranean region. Each second well is equipped with a standing valve that is seated by the second fluid in each second well. The pressure of the second fluid may be monitored and the pressure applied to the second fluid at the surface may be increased upon determining an increase in pressure during the monitoring step.

CROSS REFERENCE TO RELATED APPLICATION

This application is a division of Ser. No. 14/604,681 filed Jan. 24,2015, which claims the benefit of US Provisional Application Ser. No.61/931,575, filed Jan. 25, 2014, which is incorporated herein byreference.

BACKGROUND

The present invention relates generally to a process for inhibiting theflow of fracturing fluid through one or more subterranean wells otherthan the well(s) being hydraulically fractured so as to avoid hydraulicpressure and undesired wellbore fluids, such as gas and oil, in theupper well sections, including casing, tubulars, any artificial liftequipment, and surface equipment, and in one or more embodiments, tosuch a process wherein the flow of fracturing fluid through suchsubterranean wells is inhibited by pressuring fluid in the well(s) notbeing hydraulically fractured to seat a standing valve.

In the production of fluid from a subterranean region, a wellbore isdrilled so as to penetrate one or more subterranean zone(s), horizon(s)and/or formation(s) of interest. The wellbore is typically completed bypositioning casing which can be made up of tubular joints into thewellbore and securing the casing therein by any suitable means, such ascement positioned between the casing and the walls of the wellbore.Thereafter, the well is usually completed by conveying a perforating gunor other means of penetrating casing adjacent the zone(s), horizon(s)and/or formation(s) of interest and detonating explosive charges so asto perforate both the casing and the adjacent zone(s), horizon(s) and/orformation(s). A perforating gun may contain several shaped explosivecharges and are available in a range of sizes and configurations whichusually provide for a certain charge density and spacing of the shapedexplosive charges both vertically along the wellbore and angularly aboutthe axis of the perforating gun. In this manner, fluid communication isestablished between the zone(s), horizon(s) and/or formation(s) and theinterior of the casing to permit the flow of fluid from the zone(s),horizon(s) and/or formation(s) into the wellbore. Alternatively, thewellbore can be completed as an “open hole”, meaning that casing isinstalled in the wellbore but terminates above the subterranean regionof interest. The well is subsequently equipped with production tubingand conventional, associated equipment, such as sliding sleeves, so asto produce fluid from the zone(s), horizon(s) and/or formation(s) ofinterest to the surface. The casing and/or tubing can also be used toinject fluid into the wellbore to assist in production of fluidtherefrom or into the zone(s), horizon(s) and/or formation(s) to assistin extracting fluid therefrom.

It is often desirable to stimulate the subterranean region of interestto enhance production of fluids, such as hydrocarbons, therefrom bypumping fluid under pressure into the wellbore and the surroundingsubterranean region of interest to induce hydraulic fracturing thereof.Thereafter, fluid may be produced from the subterranean region ofinterest, into the wellbore and through the production tubing and/orcasing string to the surface of the earth by means of artificial liftssystems, such as a rod pump, as will be evident to a skilled artisan.Where it is desired to stimulate or fracture the subterranean region ofinterest at multiple, spaced apart locations along an uncased wellborepenetrating the formation, i.e. along an open hole, isolation means,such as packers, may be actuated in the open hole to isolate eachparticular location at which injection is to occur from the remaininglocations. Thereafter fluid may be pumped under pressure from thesurface into the wellbore and the subterranean region adjacent eachisolated location so as to hydraulically fracture the same. Thesubterranean region may be hydraulically fractured simultaneously orsequentially. Conventional systems and associated methodology that areused to stimulate subterranean formation in this manner includeswellable packer systems with sliding sleeves, hydraulically set packersystems, ball drop systems, and perforate and plug systems.

Often a liner is positioned and cemented within a substantial portion ofan open hole, horizontal wellbore to provide greater well stability andserviceability through the horizontal section of the open hole wellbore.A “plug-and-perf” stimulation technique may be employed in suchhorizontal wells with cemented liners. In accordance with thistechnique, a plug for obtaining tubular pressure isolation, including,but not limited to a bridge plug, frac plug, or sand plug, andperforating guns may be positioned within the horizontal section nearthe toe (end or total depth) of the horizontal wellbore. The plug isthen set and the zone is perforated by detonating the perforating gun.The plug and perforating gun are then removed from the wellbore and thefracturing fluids are pumped from the surface and diverted through theperforations into the formation by the set plug. Thereafter, anotherplug and associated perforating gun is lowered into the horizontalsection above the previously treated portion and sequentially activatedin a manner as described above. This process is repeated while typicallymoving from the toe (i.e., the distal end of the wellbore) to the heel(i.e., first point in a horizontal well trajectory where the inclinationreaches near 900) of the wellbore until the desired portion is thehorizontal section of the wellbore is entirely stimulated, i.e.fractured.

The advent of drilling horizontal wells and hydraulically fracturing thesame to improve recovery from a subterranean region, such as tightshales, has led to certain issues surrounding communication betweenwells. Prior to that, most wells were drilled in a generally verticalorientation and the spacing between these wells was approved byregulatory agencies and based on an assigned and generally understooddrainage area. In many of low-permeability reservoirs, these wells werefractured immediately after drilling, often without any attempt toproduce them before fracturing. Vertical wells were deemed spaced asufficient distance from each other to prevent any unwanted direct fluidcommunication between wells during the fracturing process. The acceptedtheory was that vertical fractures created in adjacent wells would beparallel and not intersect each other.

Presently, horizontal wells are routinely drilled and fractured to moreefficiently produce fluids from a subterranean region. However,decreased spacing requirements and the generally perpendicularorientation of fractures induced from horizontal wellbores has led toincreased communication between horizontal wellbores during and afterhydraulic fracturing. Invasion of fracturing fluid into well(s) otherthan the well(s) being fractured at a given time may result in floodingof offset(s) well and temporary loss of production. Such fluidcommunication may be a function of distance between wells and thefracture network present in a subterranean region, both naturallyoccurring and created during the fracturing process. For example,communicating wells often may be up to 3,000 feet apart, while manygovernment agencies regulating drilling may permit horizontal wellboreswith spacing as little as 500 feet from each other. Which wells will besubject to invasion of fracturing fluid during fracturing is not alwaysreadily evident to a skilled artisan due in large part to a lack ofknowledge of the natural and created subterranean fracture network.While offset well communication resulting from fracturing may betemporary, in other instances such communication may be permanent andmay cause direct cross-flow between wells, surface spills and damagewellbore integrity which may lead to subterranean contamination. Fluidpressure and undesired wellbore fluids, such as gas and oil, due tooffset well communication may also damage well equipment, such asartificial lift equipment and surface equipment.

To inhibit the consequences of communication between offset wells duringhydraulic fracturing, operators may pull equipment from the offsetwells, such as pumps and rods, run a packer by means of a tubular andset the packer at a subterranean location above the subterranean regionbeing fractured. In this manner, the offset wellbores may be sealedagainst the invasion of fracturing fluid communicated through thefractured subterranean region and the possible attendant problemsassociated therewith. However, pulling the existing equipment in a welland running and setting a packer on tubing is expensive, e.g. $300,000,and time consuming. Further, the lost production of hydrocarbons whileundergoing such operation is extremely costly and may be extended bycomplications in setting packer(s). Accordingly, a need exists for acost effective and efficient process for inhibiting flow of fracturingfluid into offset wells.

SUMMARY

A subterranean fracturing process comprises injecting a fracturing fluidunder pressure via a first well penetrating and in fluid communicationwith a subterranean region of interest so as to fracture thesubterranean region. A second fluid may be positioned within a secondwell equipped with a standing valve and penetrating and in fluidcommunication with the subterranean region. The second fluid seats thestanding valve and inhibits flow of the fracturing fluid up the secondwell.

A wellbore system for fracturing a subterranean region comprises a firstwell penetrating and in fluid communication with a subterranean regionof interest and at least one second well penetrating and in fluidcommunication with the subterranean region of interest, each of the atleast one second well equipped with a standing valve.

A process comprises applying pressure from the surface to a fluidcontained a subterranean well equipped with a standing valve andmonitoring for any decline in fluid pressure that would indicate a lossof integrity of a wellbore tubular.

BRIEF DESCRIPTION OF THE DRAWINGS

Exemplary embodiments are illustrated in the referenced figures of thedrawings. It is intended that the embodiments and the figures disclosedherein are to be considered illustrative rather than limiting.

FIG. 1 is a schematic representation of a subterranean geologic volumeof interest illustrating three wells penetrating and in fluidcommunication with a subterranean region of interest;

FIG. 2 is a perspective view illustrating the three wells depicted inFIG. 1 in greater detail;

FIG. 3 is a partially cutaway, cross sectional view of one emodiment ofa standing valve suitable for use in the present invention;

FIG. 4. is a cross sectional view of a subterranean wellbore equippedwith a standing valve assembly in accordance with an embodiment of thepresent invention; and

FIG. 5 is a cross sectional view of a subterranean wellbore equippedwith a standing valve assembly in accordance with another embodiment ofthe present invention.

DETAILED DESCRIPTION

As used throughout this description, the term “subterranean region”denotes one or more layers, strata, zones, horizons, reservoirs, orcombinations thereof, while the term “standing valve” refers to adownhole assembly, including but not limited to a valve assembly, thatis designed to hold pressure from above while allowing fluids to flowfrom below. As illustrated in FIG. 1, wells 10, 12 and 14 are depictedas being drilled from the surface 2 through the earth 4 and penetratingand in fluid communication with a subterranean region 6 of interest. Asillustrated, each well 10, 12 and 14 may have a substantially horizontalconfiguration through the subterranean region 6. Well 12 may befractured at spaced apart intervals along the generally horizontalportion thereof through the subterranean region by pumping fluid fromthe surface of the earth into the environs 6 at sufficient pressure tocreate fracture networks 22, 24, 26 and 28 that extend into environs 6away from well 12. Although not illustrated in FIG. 1, fractures 22, 24,26 and 28 may extend to and intersect with wells 10 and 14. Also,although wells 10 and 14 are illustrated in FIG. 1 as not beingfractured, one or more of these wells may have been previously fracturedand fractures 22, 24, 26 and 28 may be in fluid communication with theexisting fractures emanating from either or both of wells 10 and 14 (notillustrated), natural fractures within the region 6, or both. Inaccordance with the present invention, a process is provided forinhibiting communication into wells 10 and 14 of fracturing fluid 20pumped into well 12 to fracture the subterranean region 6.

In accordance with an embodiment of the process of the presentinvention, at least one standing valve may be positioned within at leastone of the wells penetrating a subterranean region of interest that isnot being fractured at the same time as well 12. As illustrated in FIG.2, a standing valve 32 and 42 may be positioned within either or both ofwells 10 well 14, respectively, and secured to a tubular, such as casing30 and 40, respectively. As will be evident to a skilled artisan, aparticular subterranean region of interest may be penetrated by aplurality of wells that may number a hundred or more and all wells inwhich communication of fracturing fluid from another well is desired tobe inhibited may be equipped with a standing valve in accordance withthe present invention. A well may be originally equipped with a standingvalve that may be positioned within a corresponding profile in atubular, such as casing (as illustrated in FIG. 2), casing liner orproduction tubing, or an appropriate nipple in such tubular, or includedin an assembly, tool or equipment, such as a packer assembly, which thewell may be originally equipped with. In the instance where such well isnot originally equipped with a standing valve, the standing valve may bepositioned within such a profile within a tubular within the well by anysuitable means, such as slickline, in a manner evident to a skilledartisan. Alternatively, the standing valve may be included in anassembly, tool or equipment, such as a packer assembly, which is thenlowered to a suitable position within the well, for example the top of aliner assembly, and secured therein. In any event, the standing valvemay be positioned above the top of any perforations or sliding sleevesin the well to inhibit flow of fracturing fluid and undesired wellborefluids, such as gas and oil, resulting therefrom entering into the welland acting upon the production casing, tubulars, surface valves, andartificial lift equipment as hereinafter described so as to prevent anydamage thereto.

The standing valve may be any standing valve commercially available,such as the standing valve manufactured as part of a packer assembly byWeatherford under the trade name WR, so long as the valve will shut offfluid flow upward through the tubular when sufficient fluid pressure isapplied to the valve, such as by fluid pumped through the tubular fromthe surface.

In accordance with an embodiment of the present invention as illustratedin FIG. 2, offset wells 10 and 14 may both be equipped with casing 30and 40, respectively. Standing valve 32 and 42 may be set in acorresponding profile within casing 30 and 40, respectively, above theperforations formed therein. During fracturing of subterranean region 6via well 12, suitable fluid 16 and 18 may be positioned, for example bypumping from the surface, within wells 10 and 14, respectively, to seatstanding valves 32 and 42 and suitable pressure applied to the fluid 16,18 in wells 10, 14 to ensure that fracturing fluid 20 pumped into region6 via well 12 is not communicated through wells 10 and 14 (as indicatedby the arrows in the deviated or horizontal section of wells 10 and 14in FIG. 2) to other subterranean regions or to the surface. It will bereadily understood by a skilled artisan that suitable fluids, forexample produced fluids, may be already be present in one or more of theoffset wells in an amount sufficient to commence the processes of thepresent invention without requiring fluid injection from the surfaceinto wells 10 and 14 or in an amount that requires reduced volumes ofinjected or pumped fluid as opposed to those instances in which fluid isabsent from the offset wells. While the suitable fluid 16, 18 used toseat the standing valves 32 and 42 may be a mud, preferably such fluidmay be water, brine or high salinity brine having a relatively highdensity. Further, produced water, completion fluids, such as fracturingfluid, or combinations thereof may be employed as the fluid in offsetwell(s) that is used to seat the standing valve(s) due to their onsiteavailability. The pressure of the fluid 16, 18 in wells 10 and 14 mustbe greater than the pressure of the hydrostatic fluid in each well andthe pressure of any fracturing fluid 20 communicated into wells 10 and14 from well 12 via subterranean region (as indicated by the arrows inthe deviated or horizontal section of wells 10 and 14 in FIG. 2). Fluid16, 18 may be pumped into each well 10 and 14 at the initiation ofpumping fracturing fluid 20 in well 12 and maintained during the entirefracturing operation. Fluids from subterranean region 6 may be producedvia wells 10 and 14 until shortly before fracturing operations commencevia well 12 to maximize production and lower the costs associated withthe process of the present invention.

The density of the fluids used in offset well(s), such as wells 10 and14, to seat the standing valve will impact the amount of surfacepressure that may be applied to seat a given standing valve. In general,increasing the density of the fluid used to seat a standing valve willincrease the hydrostatic pressure of the column of such fluid above andacting upon the standing valve thereby decreasing the surface pressurethat may be needed to seat the standing valve. In certain instances, thedensity of the fracturing fluid may provide the column of such fluidacting on the standing valve with sufficient hydrostatic pressure toseat the standing valve thereby initially eliminating the need to applyfurther pressure on the fluid. In such instances, the fluid should bemonitored to determine any increase in pressure from encroachingfracturing fluid from another well that would warrant the need to applysurface pressure to the fluid to ensure the standing valve remainsseated. In addition, the standing valve may be equipped with a spring orsimilar mechanical device to bias the valve into the seated or closedposition.

As wellbore pressures in excess of 8,500 psi may be encountered inoffset wells during fracturing operations, it may be preferable not topressure the fluid 16, 18 in wells 10, 14 to seat the standing valves atsuch high pressures to avoid any possibility of compromising the wellintegrity due to, for example tubular failure. Accordingly, analternative embodiment of a standing valve is illustrated in FIG. 3.which employs a different standing valve pressure/area relationship tolower the applied surface pressure needed to seat a standing valve. Mostconventional ball/seat standing valves, such as those illustrated inFIG. 2 have a substantially 1:1 pressure ratio, meaning that the surfacearea of the valve above the seat upon which introduced fluid acts issubstantially the same as the surface area of the valve below the seatupon which encroaching fracturing fluid acts. In accordance with theembodiment illustrated in FIG. 3, the upper surface area 54 of thestanding valve 52 is greater than the lower surface area 56 so thatsignificantly less pressure may be applied to the fluid from the surfaceof the well to seat the standing valve 52. While the ratio of the uppersurface area 54 to the lower surface area 56 may be varied, a preferredratio of 2:1 to 3:1 may be suitable for most applications in accordancewith the present invention.

In accordance with another embodiment of the present invention, aprocess of monitoring fluid pressure in a well comprises holdingrelatively low pressure on fluid 16, 18 seating the standing valve inone of more offset well 10, 14 while fracturing operations are commencedon well 12. If an increase in pressure on the fluid 16, 18 in wells 10,14 is observed which would indicate the communication of fracturingfluid 20 into the offset well(s), then the pressure on the fluid in theaffected well may be increased to ensure that the standing valve isproperly seated to ensure against flow of fracturing fluid through thewell. Also by including standing valves in offset wells, an operator mayemploy a method to insure well integrity comprising introducing fluidinto the well to seat the standing valve, pressuring the fluid andmonitoring any pressure decline which would indicate a loss of wellintegrity, such as a casing leak and “test” for the state.

The pressure of fluid 16, 18 within each well 10, 14 may be monitored byany suitable downhole pressure sensor as will be evident to a skilledartisan and the pressure of the fluid 16, 18 injected into each offsetwell 10, 14 adjusted to ensure that the pressure acting on the standingvalve in each well is sufficient to ensure against pressure fromfracturing fluid 20 unseating the standing valve and entering well 10 or14. Alternatively, fluid 16, 18 may be pumped into one or more of wells10, 14 when the downhole pressure sensor in such well indicates anincrease due to the influx of fracturing fluid 20 during fracturingoperations conducted on well 12. Suitable downhole pressure sensortechnology is commercially available, for example the Spotter™technology available from Aba Controls Inc. of Calgary, Canada.

To facilitate a better understanding of the present invention, thefollowing example of certain aspects of some embodiments are given. Thefollowing example should not be read or construed in any manner tolimit, or define, the entire scope of the invention.

EXAMPLE

A first well penetrates a subterranean region of interest in asubstantially horizontal manner and is equipped with a plurality ofsliding sleeves. The first well has a 10,000 ft. TVD (true verticaldepth). The region of interest has a 0.85 psi/ft. fracture gradient. Asecond well penetrates and is in fluid communication with the region ofinterest in proximity to the first well. The second well is equippedwith a ball and seat standing valve at approximately 9,500 ft. TVD. Thestanding valve has a 1:1 pressure ratio. Fracturing operations arecommenced through at least one of the plurality of sliding sleeves inthe first well. Fluid pressure beneath the standing valve in the secondwell is approximately 8,300 psi. A 9.6 lb/gal brine is introduced intothe second well to seat the standing valve. As the hydrostatic pressureof this brine in the second well is 4,742 psi, a surface pressure atleast as great as 3,500 psi is required to ensure that the standingvalve remains seated during the fracturing operation thereby inhibitingflow of fracturing fluid up the second well. Recognizing that pressurefrom the fracturing operations on the first well may be communicated tothe second well, a surface pressure of 3,500 psi is applied to the brinein the second well.

A third well penetrates and is in fluid communication with the region ofinterest in proximity to the first well. The third well is equipped witha ball and seat standing valve at approximately 9,500 ft. TVD. Thestanding valve has a 1:1 pressure ratio. As previously mentioned,fracturing operations are commenced through at least one of theplurality of sliding sleeves in the first well. Fluid pressure beneaththe standing valve in the third well is approximately 8,300 psi. A 14lb/gal brine is introduced into the third well to seat the standingvalve. As the hydrostatic pressure of this brine in the third well is6,916 psi, a surface pressure at least as great as 1,384 psi is requiredto ensure that the standing valve remains seated during the fracturingoperation thereby inhibiting flow of fracturing fluid up the third well.Recognizing that pressure from the fracturing operations on the firstwell may be communicated to the third well, a surface pressure of 1,384psi is applied to the brine in the third well.

After fracturing operations, the second and third wells are returned toproduction and the brine is produced to the surface and not lost to thesubterranean region of interest.

While a ball and seat valve and the valve of FIG. 3 having a pressureratio greater than 1:1 have been illustrated and described above, it iswithin the purview of a skilled artisan to employ any other downholevalve assembly that are designed to hold pressure from above whileallowing fluids to flow from below in the present invention.

As previously mentioned, the standing valve assembly (i.e. an assemblyincluding a standing valve secured to a packer) may be positioned abovethe top of any perforations or sliding sleeves in a given well. As willbe evident to a skilled artisan, subterranean wells may be completed indifferent manners which will dictate the exact placement of the standingvalve. As illustrated in FIG. 2, the standing valve assembly 64 issecured to a tubular, such as casing, that may be cemented within asubterranean wellbore. A rod pump and associated rods may also bepositioned in the cemented casing above the packer and standing valve.Alternatively, a casing 61 that is secured within a wellbore 60 bymeans, such as cement 62, may terminate above or in the horizontalsection and the wellbore may be equipped with a liner 70 that extendsinto the horizontal or deviated section of a subterranean wellbore andis secured therein by means, such as cement 71 (FIG. 4). One or moresets of perforations 74 may extend from the liner 70 through the cement71 to establish fluid communication with region 6. The standing valveassembly 64 may be secured in a corresponding profile within casing 61as will be evident to a skilled artisan. In another embodiment of thepresent invention illustrated in FIG. 5, the liner 70 is not cemented inthe horizontal or deviated section of the subterranean well bore. Inthis embodiment, zonal isolation may be accomplished by means of slidingsleeves 76 in the liner and associated open hole packers 78 positionedon the outside of the liner 70 between the sleeves and in sealingengagement with the open hole. A rod pump and associated rods may alsobe positioned in the cemented casing above the standing valve assembly64 in either of the embodiments illustrated in FIGS. 4 and 5.Alternatively, the standing valve assembly 64 may be secured in aprofile in the top of the liner 70 above perforations 74 in FIG. 4 andsleeves 76 and open hole packers 78 in FIG. 5 in lieu of a profile incasing 61 as will be evident to a skilled artisan.

Certain embodiments of the methods of the invention are describedherein. Additionally, although figures are provided that schematicallyshow certain aspects of the methods of the present invention, thesefigures should not be viewed as limiting on any particular method of theinvention. As used herein, terms such as “upper” and “lower”, “upwardly”and “downwardly”, “above” and “below” and other like terms indicatingrelative positions within a subterranean well or wellbore are used inthis application to more clearly describe some embodiments of theinvention. However, when applied to equipment and methods for use insubterranean wells and wellbores that are deviated from a verticalorientation, including horizontal, such terms may refer to positionswithin the deviated or horizontal plane, or other relationship asappropriate, rather than the vertical plane. For example, the term“above” as applied to a deviated or horizontal well or wellbore mayrefer to a position that is closer to the surface of the earth along thewell or wellbore than the point of reference.

While a number of exemplary aspects and embodiments have been discussedabove, those of skill in the art will recognize certain modifications,permutations, additions and subcombinations thereof. It is thereforeintended that the following appended claims and claims hereafterintroduced are interpreted to include all such modifications,permutations, additions and sub-combinations as are within their truespirit and scope.

What is claimed is:
 1. A wellbore system for fracturing a subterraneanregion comprising: a first well penetrating and in fluid communicationwith a subterranean region of interest; and at least one second wellpenetrating and in fluid communication with the subterranean region ofinterest, each of said at least one second well equipped with a standingvalve.
 2. The wellbore system of claim 1 wherein each of said at leastone second well is equipped with a wellbore pressure monitoring system.3. The wellbore system of claim 1 wherein the standing valve has anupper surface and a lower surface.
 4. The wellbore system of claim 1wherein the ratio of the upper surface to the lower surface issubstantially 1:1.
 5. The wellbore system of claim 1 wherein the ratioof the upper surface to the lower surface is greater 1:1.
 6. The processof claim 18 wherein the ration of the upper surface to the lower surfaceis from about 2:1 to about 3:1.
 7. A process comprising: applyingpressure from the surface to a fluid contained in a subterranean wellequipped with a standing valve; and monitoring for any decline in fluidpressure that would indicate a loss of integrity of a wellbore tubular.